Method and apparatus for distinguishing hydrocarbon from fresh water in situ

ABSTRACT

Method and apparatus for distinguishing oil from fresh water in situ in a subsurface geological formation are proposed which utilize the anomalous response of a neutron porosity tool to some oils. Apparent porosity derived from a neutron porosity investigation tool which measures spatial neutron flux distribution is compared to the porosity derived from a second investigating tool whose response is not or at least is less sensitive to the hydrogen density of the formation fluid than is the neutron porosity tool. Where a real difference is evident, oil rather than fresh water is indicated.

The subject matter of this invention is related to subject matterdisclosed in U.S. patent application Ser. No. 328,880 of John J. Ullo,filed of even date herewith and assigned to the same assignee of thepresent invention.

FIELD OF THE INVENTION

The present invention relates generally to the field of theinvestigation of characteristic properties of subsurface geologicalformations penetrated by a borehole by means of an instrument orinstruments passed therethrough. More specifically, the presentinvention relates to the determination of the identity of the fluid inthe formation: whether it be a hydrocarbon or water. More specificallystill, the present invention relates to a neutron based technique andapparatus useful for distinguishing between some oils and water.

BACKGROUND OF THE INVENTION

It should go without saying that it is highly desirable to be able todistinguish between oil and water in a geological formation penetratedby a borehole. The ability to do so enables one to determine, amongother things, if a porous formation contains oil or water, the rate ofmovement and position of the oil/water interface during well production,and whether the water driving fluid has broken through to the productionwell in a water flood secondary production operation. It has beenconventional in the past to distinguish between oil and water by meansof a resistivity tool which reads a low resistivity when the formationis saturated with saline water, a good conductor; and a high resistivitywhen the formation is saturated with oil, an insulator.

It has also been conventional in the past to distinguish between oil andwater by taking advantage of the differences in the macroscopic neutronabsorption cross section of oil and the normally saline formation water.Since the saline formation water contains chlorine which has a ratherhigh neutron capture cross section and since oil does not, neutron toolshave been developed which essentially measure the macroscopic neutroncapture cross section (Sigma).

For example, U.S. Pat. No. 3,566,116 (reissued July 8, 1975 as U.S. Pat.No. Re. 28,477); U.S. Pat. Nos. 3,691,378; and 4,055,763 illustratevariations of one such technique for determining Sigma in which a pulsedneutron source is utilized to irradiate the formation with a repetitiveburst of fast neutrons in order to permit a time evaluation of theneutron population in the resultant neutron cloud. Typically, thisevaluation is accomplished by detecting capture gamma rays which resultwhen thermalized neutrons of the cloud are captured or absorbed by anucleus of a constituent element in the formation. In such a timeevaluation, advantage is taken of the fact that the neutron clouddensity decays exponentially, with the characteristic decay time being afunction of the macroscopic neutron absorption cross section of theformation. The macroscopic neutron absorption cross section is the sumof the neutron absorption of the elemental constituents of the formationand of its contained fluids.

While these neutron tools and techniques are quite effective indistinguishing between oil and water under normal circumstances, anumber of limitations have been encountered. One such limitation is thesituation in which, for one reason or another, the non-oil fluid in theformation is fresh water rather than saline water. In this circumstanceit is not possible using the above described pulsed neutron technique todistinguish between oil and water since the differences between theneutron capture cross section of the two formation fluids (oil and freshwater) is not large enough to permit their differentiation.

A further limitation that the pulsed neutron techniques for determiningSigma have encountered is their inability to properly determine Sigma ina formation containing large amounts of naturally radioactive elementssuch as thorium, uranium and potassium. Accumulations of one or more ofthese radioactive elements may produce a gamma-ray background thatobscures the desired information relative to the neutron cloudestablished by the pulsed neutron source. Unfortunately, accumulationsof naturally occurring radioactive elements are often encountered in aproducing well. When these radioactive elements are found dissolved inthe formation fluids, they may precipitate out of solution andaccumulate at the well casing perforations through which the formationfluids are flowed. This creates a radioactive deposit that produces arelatively high gamma-ray background which interferes with the detectionmethod of the pulsed neutron technique. Thus, information regardingSigma and oil/water movements in the very formation zones of greatestinterest may be unavailable due to this obscuring background.

An additional limitation with the pulsed neutron technique isencountered in wells that have fresh water in the well borehole, eventhough saline water is present in the formation. In such a circumstance,some neutrons from the neutron burst are thermalized and linger in thefresh water of the borehole, giving rise to an interfering "diffusion"background. This effect of course does not occur in those boreholeshaving saline water since the chlorine is a strong neutron absorberwhich rapidly scavenges the diffusion neutrons. The "diffusion"background is a particularly bothersome phenomenon for the pulsedneutron technique since the determination of the characteristic decaytime following the neutron burst relies on the detection of neutronfluxes whose intensities decrease with time to relatively small values.As a result, the "diffusion" background becomes large relative to theneutron flux of interest so as to obscure the information bearingsignal.

In view of the difficulties and limitations inherent in the pulsedneutron technique, one naturally seeks other neutron instruments andtechniques that might be suitable for distinguishing between oil andwater in those very circumstances there the pulsed technique is lacking.The other conventional neutron instrument used in logging oil wells iscommonly referred to as the neutron-neutron tool since it contains acontinuous neutron source for irradiating the formation and neutrondetectors for detecting the spatial distribution of neutrons establishedby the source. It is conventional to utilize this tool to measureporosity of the formation under investigation. U.S. Pat. No. 3,483,376,issued Dec. 9, 1969, entitled "TWO NEUTRON DETECTOR EARTH FORMATIONPOROSITY LOGGING TECHNIQUE", commonly assigned to the assignee of thepresent invehtion, describes in detail an illustrative embodiment ofsuch a neutron-neutron tool.

Interestingly, in the past, very little has been understood about whichparameters of a medium influence porosity response in an investigatinginstrument. This is indeed the case for neutron-neutron or neutron-gammaporosity tools. Such neutron tools utilize a source for emittingneutrons into the adjacent formations and subsequently or simultaneouslydetect the spatial distribution of the resultant neutron cloud througheither the direct detection of neutrons or through the detection ofgamma rays which are created when a neutron is absorbed in the nucleusof an atom of the formation.

Following emission from the source, the neutrons travel through theformation and lose energy by collision with the nuclei of the atoms ofthe formation. When the energy level of the neutrons is reduced ormoderated sufficiently, they may be detected and counted by theinvestigating instrument. Generally, it is assumed, that primarily thehydrogen index (i.e., the number of hydrogen atoms per unit volume ofthe formation fluid) is responsible for the spatial distribution of thecloud of neutrons. Since hydrogen is the only element whose nuclear massresembles that of the neutron, hydrogen is the most effective element inreducing the energy level of the neutrons to a level at which they areeventually detected. In general, the formation pore spaces are filledwith either water or liquid hydrocarbons which both contain hydrogen.Thus, this type of neutron log is essentially a record of the hydrogenatom density of the rocks surrounding the borehole. Previously, theneutron log has been considered, therefore, to be a measure of theformation porosity. It is well recognized that gas, on the other hand,will alter this porosity determination since the gas is much less densethan its oil liquid counterpart.

U.S. Pat. No. 4,095,102 issued on June 13, 1978 to Tixier and assignedto the Assignee of the present patent, compares a value of porosityderived from an epithermal neutron-neutron (gamma) tool with a value ofporosity derived directly from a measurement of the thermal neutronabsorption characteristic of the formation and value of the watercomponent of the formation. Where a difference is noted, hydrocarbon maybe expected. In a manner similar to those techniques described earlierthat utilize pulses of neutrons to determine a characteristic decay timedependent on macroscopic neutron capture cross section and hence aporosity, the disclosed technique requires saline water in theformation.

SUMMARY OF THE INVENTION

It has not been heretofore thought possible to distinguish formation oilfrom formation water by a neutron technique unless the water containsneutron absorbers (such as chlorine) which are absent in the formationoil. The conventional wisdom in the field of oil exploration has beenthat oil and fresh water "look alike" when examined by neutronmoderation type as opposed to neutron absorption type investigatingtools. Indeed, fresh water and oils which typically are used inlaboratory test formations and many oils and waters in earth formationsdo "look" indistinguishable. This common assumption is expressed in U.S.Pat. No. 3,721,960 which states "thus, it can be said that this type ofneutron log is essentially a record of the hydrogen atom density of therocks surrounding the borehole. Since the formation pore spaces aregenerally filled by either water or liquid hydrocarbons which have aboutthe same amount of hydrogen, the neutron log does not distinguishbetween oil and water . . ."

However, recent investigations of atypical oils used in laboratoryexperiments have led to the startling and previously unsuspecteddiscovery that many world crude oils, especially those looselycategorized as "heavy crudes", have properties sufficiently differentfrom fresh water to permit a logging technique that could be usedsuccessfully to distinguish between oil and fresh formation water.

Specifically, it has been discovered that neutron transport through manycrude oils is sufficiently different from neutron transport throughfresh water so as to be detectable. It is hypothesized that the observedneutron transport differences are attributable to the influence onneutron transport exerted by the number of hydrogen nuclei present inthe medium of transport. Thus, it is herein proposed that media withhigh hydrogen densities cause the creation of detectably differentneutron fluxes than those media with lower hydrogen densities.

It has been assumed in the past that both water and oil have about thesame amount of hydrogen, or in other words, have approximately the samehydrogen index or hydrogen density. Accordingly, prior neutronmoderation type tools were believed to be incapable of distinguishingbetween oil and water. Recent experimental investigations and theirclose evaluation has led to the conclusion that oil and water do notnecessarily have the same hydrogen densities. In fact, it has beendiscovered that the differences between the hydrogen densities of waterand some oil, albeit small, may be large enough to have a measurableeffect on the porosity response of the neutron investigating instrument.It has also been discovered that additional differences between oil andwater, such as the presence of carbon in oil and its absence in water,and the presence of oxygen in water and its absence in oil, may producean additional effect on porosity response which might further assist inthe ability of a neutron tool to distinguish between oil and water.

It has been found that these differences between some oils and watertend to cause the apparent porosity registered by a neutron tool in acrude-oil saturated formation to be higher than true volumetric porositywhen a tool calibration based on fresh water filled porosity is used.With this realization, it is proposed to take advantage of the effect toidentify the presence of oil by using a combination neutron porositylogging tool with another porosity logging tool to look for cleanformations (as determined, for example, by the natural gamma-ray log)where the porosity indicated by the neutron tool exceeds that derivedfrom the other porosity tool. Alternatively, one might first log a knownoil bearing formation with a neutron porosity logging tool, produce theformation oil with steam flood or water flood, re-log the formation withthe neutron porosity logging tool and compare the pre- and post-logs todetermine information about the production of the formation.

It is therefore proposed that the oil/water content of the fluid withina geological formation may be investigated, broadly speaking, byirradiating the formation with neutrons, and by measuring a propertyindicative of neutron transport through the matrix and the fluidcomprising the formation to derive an indication which represents theinfluence of the formation fluids on neutron transport and which issubstantially devoid of the influence of the matrix on neutrontransport. This information may then be used to determine acharacteristic of the fluid in the formation.

More specifically, the neutron flux distribution resulting from theirradiation is measured and used to derive a first signal which is afunction of both formation porosity and hydrogen density of the fluid inthe formation. The presence of oil versus water in the formation is thendetermined by deriving from the same geological formation a secondporosity signal that is either less affected by the nature of theformation fluid, whether water or oil, than the first signal, such as isavailable from a gamma-gamma density tool or a sonic tool or that isobtained following the change of the formation fluid to a fluid having,say, a different hydrogen density, and combining the signals todetermine their differential. Where the first porosity signal exceedsthe second porosity signal, oil as opposed to water may be suspected.The step of detecting the neutron flux distribution may includedetecting the spatial neutron flux distribution by detecting neutronflux amplitudes at one or more points spaced from the neutron source. Inaddition, the neutron detection step may comprise the detection of theepithermal neutron flux distribution.

In a variation of the invention, the formation is irradiated in twosteps with neutrons having different average energy levels in order tomeasure the spatial neutron flux distribution resulting from each.Comparison of the resultant signals yields an indication of the presenceof oil or of water. One of the average energy levels is chosen such thatthe total cross section mismatch between oil and water is small, whilethe other is chosen such that the total cross section mismatch betweenoil and water is large relative to that of the other.

BRIEF DESCRIPTION OF THE DRAWINGS

The present invention may be better understood and its numerous objectsand advantages will become apparent to those skilled in the art byreference to the accompanying drawings which generally illustrate theconcepts of the present invention in which:

FIG. 1 schematically illustrates an embodiment of the invention in whicha neutron porosity log derived from a neutron logging tool is combinedwith a porosity derived from a different logging tool to yield anindication of oil versus water;

FIG. 2 is a plot of hydrogen density versus carbon density for asampling of world crude oils;

FIG. 3 is a graph showing the apparent change in porosity in percent asa function of an effective total cross section index for hydrocarbons;and

FIG. 4 is a plot illustrating the family of curves of hydrocarbonshaving constant densities and hydrogen densities as a function ofporosity and apparent change in porosity.

DESCRIPTION OF THE BEST MODE OF THE INVENTION

While the invention is susceptible of various modifications andalternative constructions, there is shown in the drawing and there willhereinafter be described, in detail, a description of the preferred orbest known mode of the invention. It is to be understood, however, thatthe specific description and drawing are not intended to limit theinvention to the specific form disclosed. On the contrary, it isintended that the scope of this patent include all modifications andalternative constructions thereof falling within the spirit and scope ofthe invention as expressed in the appended claims, to the full range oftheir equivalents.

An illustrative embodiment of a practical apparatus embodying theprinciples of the invention is shown in FIG. 1. A borehole logging toolstring 10 is shown consisting of a pair of tools 12 and 14 suspended byan armored cable 18 in a borehole 22 formed in a geological formation20. Cable 18 comprises insulated conductors that electrically connectthe logging equipment via a down-hole digital telemetry cartridge 16with an up-hole telemetry system 24 and a data processing system 28 atthe earth's surface. The data processing system 28 may comprise adigital apparatus such as a PDP-11/34 computer made by the DigitalEquipment Corp. and specially modified, as by stored instructions, tocarry out the present invention. A winch (not shown) is located at thesurface and is used to lower and raise the tool string 10 in theborehole 22 to traverse earth formations 20 by amounts detected by adepth monitoring apparatus 30. Signals indicative of tool depth in theborehole are delivered from the depth monitoring system 30 to the system28.

The tool string includes a neutron porosity logging tool 12 and aporosity logging tool 14 of a different type. The sonde portion of theneutron porosity tool contains a neutron source 32, having a yield oftypically 4×10⁷ neutrons per second. Usually, the source 32 is a"chemical" neutron source, for example, a mixture of plutonium andberyllium or americium and beryllium. Alternatively, neutron source 32may comprise a neutron generator of the ion accelerator type, an exampleof which may be found described in U.S. Pat. No. 3,775,216 assigned tothe assignee of the present invention. Each of these neutron sources isisotropic and emits neutrons with equal probability in all directions.

The neutrons emitted from source 32 diffuse through the formations 20and are detected by a neutron detection system which may consist ofeither a single detector system or a dual detector system which ispreferred. In the dual detector system, neutrons are registered by anear-spaced neutron detector 34 and a far-spaced detector 36: each ofwhich generate a signal indicative of neutron flux distribution which inturn is related to the neutron transport properties of the neutronsthrough both formation matrix and formation fluid. Typically, thesedetectors each comprise a hollow cylindrical cathode filled with aneutron sensitive gas, He³ or boron-triflouride, for example. An anodewire (not shown) in the center of the cylinder creates a voltagegradient through the gas-filled cylinder that enables ionized nuclearparticles, produced as a consequence of neutron absorption within thegas nuclei, to establish charged pulses in the detector electrodes. Thefar-spaced detector 36 has a much larger volume than the near-spaceddetector 34 and is typically filled with the He³ gas at a higherpressure so as to enhance its sensitivity to neutrons. A neutron shield(not shown) is typically positioned between the near detector 34 and thesource 32 in order to reduce the direct irradiation of the near detectorby neutrons from the source and in order to increase the porositysensitivity of the tool.

Near and far detectors 34 and 36 preferably may be designed to detectepithermal neutron populations as opposed to thermal neutronpopulations. In such a case, the epithermal neutron detectors aresimilar to the thermal neutron detectors but include a cadmium or otherneutron absorbing sleeve which preferentially absorbs neutrons havingenergies below an energy threshold characteristic of the shieldingmaterial. In addition, due to the decreased counting rates whendetecting epithermal neutrons, detectors 34 and 36 may be located atoptimal distances closer to the source than would be the case forthermal neutron detectors and may be pressurized to a greater degreethan thermal neutron detectors.

Pulses from detectors 34 and 36 are accumulated in appropriate circuitry(not shown) in order to generate count rate signals proportional to theneutrons detected per second by each of the individual detectors. Thesesignals are indicative of the spatial neutron flux distribution at theparticular source-detector spacing. Alternatively, detectors 34 and 36and the associated electronic circuitry may generate signals indicativeof the total energy deposited in the respective detectors, which isfunctionally related to the count rate. For purposes of convenience, thesignals generated by detectors 34, 36 will hereafter be referred to interms of count rates but it will be recognized that the invention is notso limited. These signals are transmitted in a known manner with knownequipment to the surface instrumentation via cable 18 after undergoingvarious degrees of signal processing and conditioning dependent upon thetelemetry equipment provided in the tool string and at the surface.

The second tool 14 in the tool string 10 is a tool of the type thatproduces an indication of porosity that is less affected by the neutrontransport properties of the formation than neutron porosity tool 12.Ideally, this porosity tool is responsive to the pore space in theformation matrix but not to the matrix itself. Tool 14 may consist ofeither a second type of neutron tool that has a different sensitivity toporosity (or to the neutron transport properties of the fluid in theformation porosity) than the tool 12, such as a sidewall epithermalneutron tool (for example, U.S. Pat. No. 3,823,319), or it may consistof a completely different type of tool such as a gamma-gamma porositytool (such as U.S. Pat. No. 4,048,495) which is responsive to gamma-rayflux, or a sonic tool (U.S. Pat. No. 3,231,041), either of which producean indication of porosity that is independent of the neutron transportproperties of the formation. Each of these tools are known in the art ofhydrocarbon well logging so that a detailed description will be omittedfor the sake of conciseness.

In the event that first tool 12 and second tool 14 are both neutrontools, the first tool 12 may consist of a neutron tool of the typepreviously described which operates with a source whose average energyis in the order of 600 keV. while the second neutron tool may consist ofan epithermal tool whose average energy is on the order of 4.5 MeV.

The signals from the detectors 34 and 36, as well as the signalsgenerated by the second type of porosity tool 14, after having beentransmitted to and received by the surface processing circuitry 28, areconverted according to the principles of the present invention intotangible representations of porosity in the form of a log or trace overa depth range. Conversions of the raw data into indications of porosityare made in the functional elements 38 and 40: each of which may befunction formers of the appropriate type for the data treated. Forexample, neutron porosity function former 38 may consist of circuitryfor taking the ratio of the near and far detector count rates and thenconverting the ratio into porosity according to a response curve of aknown shape which characterizes the neutron porosity tool 12 of the toolstring. Similarly, function former 40, in response to the raw dataderived from the other porosity logging tool 14, converts the data intoindications of porosity according to techniques well known to besuitable for the particular logging tool 14 in use.

Having determined indications of porosity from each of the tools 12 and14, the present invention proposes that the porosity indications becompared in order to distinguish between oil and water filling theformation porosity. As has been previously mentioned, it has beendiscovered that the neutron porosity tool responds differently to someoils in the formation when compared to the manner in which it respondsto water in the formation. It is believed that this effect isattributable to the different neutron transport characteristics of thoseoils as opposed to the neutron transport characteristics of water. Aspreviously discussed, the neutron transport characteristic of both oiland water is primarily determined by the hydrogen density of the fluid.However, it is also recognized that the presence of carbon and the lackof oxygen in oil, and the presence of oxygen and the lack of carbon inwater also has an effect.

FIG. 2 is an illustration graphically showing the hydrogen and carbondensities for a number of world crude oils. Overlying this plot are aplurality of curves which show the percent change in porosity due to thecombined influences of the hydrogen density and the carbon density ofthe oil determined by the neutron tool with the oil in the formationrelative to the "true" porosity of the formation. It will be recognizedthat the "true" porosity is that porosity that the second porosity tool14 would measure and that the neutron tool 12 would measure if theporosity of the formation contained water. As can be seen, the #2 fueloil point falls relatively close to the line indicating no change inporosity relative to the "true" porosity. In fact, the fuel oil point isso close as to be indistinguishable from neutron tool measurementerrors. Thus it can be seen that previous experimental arrangements thathave been run with #2 fuel oil in the formation, were unlikely to detectthe effect which forms the basis for the present invention.Nevertheless, it can also be seen that there are a large number of worldcrude oils that produce an apparent change in porosity that issignificantly larger than tool measurement error and therefore shouldproduce a detectable effect.

In order to further quantify the effect of the influence of the hydrogenand carbon densities on neutron transport, FIG. 3 is a graph showing theapparent change in porosity as a function of an effective total crosssection index for hydrocarbons. The effective total cross section indexfor hydrocarbons is defined as the total effective cross section ofhydrocarbon (averaged over source neutron energies) divided by the totaleffective cross section of water. The three curves drawn for formationshaving porosities of 15, 26 and 35 porosity units, illustrate that therelative change in porosity is practically independent of the volumetricporosity, that a hydrocarbon with a total effective cross section whichis similar to that of water will be indistinguishable from water andthat the possibility of distinguishing oil from water increases linearlywith the total effective cross section of the hydrocarbon.

It is thought that these results are explained by the fact that theneutron tool's response is related to the distribution of firstcollisions of high energy source neutrons. This so-called "transportedsource strength" is in turn governed mainly by the total cross sectionsof the medium at source neutron energies. Basically then, porosityvariations are equivalent on a one-to-one basis to variations in thetotal effective cross sections which in turn affect the strength of thehigh energy neutron source especially at the far detector. At a givenvolumetric porosity, the substitution of oil for water can also alterthe total cross section which then manifests itself with the neutrontool as a different apparent porosity response. Hence, a larger apparentporosity is observed when oil is present in the porosity of theformation than when water is present.

As a result, one way of practicing the invention would be to compare thesignals from the function formers 38 and 40 by means of a subtractioncircuit 42 and a comparator circuit 44. Inasmuch as differences ofsomething like two porosity units is not likely to be significant due tomeasurement uncertainties, comparator circuit 44 may be set to respondonly to differences greater than two P.U. Differences greater than twoP.U. however, may be recorded by recorder-plotter 26 as indications ofoil. Recorder-plotter 26 also records the individual porosity signalsderived from function formers 38 and 40. Indeed, the plotting apparatus26 may be arranged to plot traces of porosity from the neutron porositytool and from the other porosity tool so that they overlay one anotherin order to better highlight the presence and magnitude of thedifferences.

It will be appreciated that if the oil response is related to thedifference in total cross sections between oil and water at sourceneutron energies, then the magnitude of the effect can be enhanced byemploying neutrons at energies where the total cross section mis-matchbetween oil and water is greatest. Two possibilities present themselves.Two neutron sources of different energies could be used: one where thecross section mis-match is small and one where it is large. Differentapparent porosities derived from the two sources could be an indicatorof oil. Source neutron energies could be "tailored" by judicious choiceof shielding. As an example, neutrons produced by a deuterium-deuterium(D,D) accelerator neutron generator may be of particular interest since(D,D) accelerator produced neutrons have energies of 2.45 MeV which isjust above a minimum in the water cross section due to the oxygenanti-resonance. This minimum is not present in an oil saturatedformation.

The above description of the present invention has been in the contextof logging a subsurface geological formation in order to distinguishbetween oil and water. This ability may find special value in the areaof production logging where it is important to determine the oil-waterinterface both before, during and after production of the oil from thewell. In this application, an initial series of logs would be run inorder to identify the location of the oil-water interface prior to oilproduction. Logs obtained after production may then be compared to theoriginal log to indicate the degree of movement of the oil-waterinterface as a measure of the rate of oil production, water coneing,etc.

As a further application of the concepts of the present invention, it ispossible to use the magnitude of the difference between the truevolumetric porosity and the apparent porosity measured by the neutrontool to determine the hydrogen density of the oil in the formation.Furthermore, if the fluid density of the formation fluid is known, thenit becomes possible to determine the hydrogen/carbon weight percent ofthe formation fluid in situ. These quantities may be of tremendous valuein the commercial evaluation of the hydrocarbon reservoir and maygreatly assist in the decision to case and cement the borehole andproduce the well or in the decision of which hydrocarbon bearing zonesin a well should be produced and which should be passed over. Thesefunctions are accomplished in the functional element 46 entitledhydrogen and carbon density circuitry: more of which will be describedbelow.

FIG. 4 illustrates the family of curves for oils having differenthydrogen densities but constant carbon densities plotted on a graph ofporosity versus apparent porosity difference as determined from acomparison of the neutron porosity with the value of porosity determinedfrom the other porosity tool 14. With both the apparent change inporosity and porosity as inputs, element 46 determines, by means of afunction former, by means of a chart similar to FIG. 4, or by means of alook up table, the corresponding hydrogen density. As can be seen fromFIG. 2, hydrogen density of the oil does not uniquely correspond to asingle carbon density so that the determination of hydrogen density fromFIG. 4 is subject to some uncertainty due to the effect of the carbondensity of the oil.

Element 46 may now enter an iterative type of analysis in order tofurther refine the determination of hydrogen density as well as toprovide a determination of carbon density. The further refinementrequires, however, further information about the fluid density (ρ_(b))of the formation fluid and the density of the matrix of the rock of theformation. Such further information may be provided by the owner of theoilwell or fluid density may be calculated from formation bulk densityand true porosity log values available from the gamma-gamma density tool(ρ_(b)) and from the sonic porosity tool (φΔt porosity) respectively bythe well known equation

    ρ.sub.b =ρ.sub.ma (1-ρ)±ρ.sub.f φ.

Having obtained a first estimate of the hydrogen density (ρ_(h)) of theoil, element 46 then may determine a first estimate of the carbondensity (ρ_(c)) from the relationship ρ_(f) =ρ_(h) +ρ_(c). With firstestimates of both hydrogen density and carbon density, the informationcontained in the graph of FIG. 2 may then be utilized to determine afirst estimate of the difference in porosity that should be expectedfrom the effects of the particular hydrogen density and the carbondensity on the porosity response of the neutron tool when compared totrue porosity. If the first estimate of the porosity differencedetermined in this manner differs from the porosity differencecalculated by element 42, then a series of perturbations to the hydrogendensity may be made and the process repeated iteratively until theestimated porosity difference and the detected porosity difference havebeen made to agree within the convergence criteria. At this point,element 46 reads out its results to recorder/plotter 26 which alsorecords and/or plots the other items of information in the form of depthvarying traces of neutron porosity (φ_(n)), true porosity (φ), porositydifference (Δ.sub.φ), hydrogen density (ρ_(h)), carbon density (ρ _(c)),as well as any other combination of these desired such as hydrogenweight percent or hydrogen density to carbon density ratio.

We claim:
 1. A method for investigating the oil/fresh water content ofthe fluid within a geological formation;a. irradiating said geologicalformation with neutrons; b. detecting the resultant neutron fluxdistribution and generating therefrom a first signal indicative offormation porosity; c. deriving from said geological formation a secondsignal indicative of formation porosity but which is less affected bythe nature of the pore fluid whether it be fresh water or liquidhydrocarbon than said first signal; and d. comparing said first andsecond signals to obtain an indication of the presence of oil versusfresh water in said formation.
 2. The method as recited in claim 1,wherein said comparing step includes the step of combining said firstand second signals to generate a signal proportional to the differentialtherebetween, said differential signal signifying the presence of oilversus fresh water in said formation.
 3. The method as recited in claim1, wherein said irradiating step includes irradiating said geologicalformation with neutrons having an average source energy selected suchthat the total effective neutron scattering cross section of oil islarger than that of fresh water.
 4. A method for distinguishing oil fromfresh water in a geological formation traversed by a borehole,characterized by the steps of:a. irradiating said geological formationwith neutrons having a first average source energy selected such thatthe difference between the total neutron cross section of oil and thetotal neutron cross section of fresh water has a first value; b.detecting neutrons resulting from step a. and generating a first signalindicative thereof; c. irradiating said geological formation withneutrons having a second average source energy different from said firstaverage source energy, said second average source energy being selectedsuch that the difference between the total neutron cross section of oiland the total neutron cross section of fresh water has a second valuedifferent from said first value; d. detecting neutrons resulting fromstep c. and generating a second signal indicative thereof; and e.comparing the signals of steps b. and d. in order to obtain anindication of the presence of oil or of fresh water.
 5. The method asrecited in claim 4 wherein each step of detecting neutrons includes thestep of detecting a spatial neutron flux distribution.
 6. The method asrecited in claim 4 wherein one of said steps of detecting neutronsincludes the step of detecting a neutron flux amplitude at a singlepoint.
 7. The method as recited in claim 6 wherein said irradiating stepincludes irradiating said geological formation with neutrons having anaverage source energy selected such that the total effective neutronscattering cross section of oil is larger than that of fresh water. 8.The method as recited in claim 4 wherein said first and second averagesource energies are selected such that the difference between the totaleffective neutron scattering cross sections of oil and fresh water isgreater for neutrons having said first average source energy than forneutrons having said second average source energy.
 9. The method asrecited in claim 4, wherein said first average source energy is suchthat the total neutron scattering cross-section mismatch between oil andfresh water is less than that for said second average source energy. 10.A method for distinguishing oil from fresh water in a geologicalformation traversed by a borehole, characterized by the steps of:a.irradiating said geological formation with neutrons; b. detecting theneutron flux distribution resulting from step a. and generating a firstsignal indicative of formation porosity therefrom; c. irradiating saidgeological formation with gamma rays; d. detecting the gamma ray fluxresulting from step c. and generating a second signal indicative offormation porosity therefrom; e. comparing the porosity signals of stepsb. and d. and f. in response to the comparison of step e. generating andrecording a signal whose value is indicative of the presence of oil orof fresh water in the geological formation.
 11. The method ofdistinguishing oil from fresh water as recited in claim 10 wherein saidstep of detecting the neutron flux distribution includes the step ofdetecting the epithermal neutron flux distribution.
 12. The method asrecited in claim 10 wherein said irradiating step includes irradiatingsaid geological formation with neutrons having an average source energyselected such that the total effective neutron scattering cross sectionof oil is larger than that of fresh water.
 13. A method fordistinguishing oil from fresh water in a geological formation traversedby a borehole, characterized by the steps of:a. irradiating saidgeological formation with neutrons; b. detecting the neutron fluxresulting from step a. and generating a first signal indicative offormation porosity therefrom; c. transmitting sound waves into saidgeological formation; d. detecting sound waves returning from theformation resulting from step c. and generating a signal indicative offormation porosity therefrom; e. comparing the porosity signals of stepsb. and d. and f. in response to the comparison step of step e,generating and recording a signal whose value is indicative of thepresence of oil or of fresh water in the geological formation.
 14. Themethod as recited in claim 13 wherein said irradiating step includesirradiating said geological formation with neutrons having an averagesource energy selected such that the total effective neutron scatteringcross section of oil is larger than that of fresh water.
 15. A systemfor distinguishing oil from fresh water in a geological formationtraversed by a borehole, characterized by:a. a neutron source forirradiating said geological formation with neutrons; b. a detectorsystem for detecting the resultant neutron flux distribution andgenerating therefrom a first signal indicative of formation porosity; c.an investigatory system for deriving from said geological formation asecond signal indicative of formation porosity but which is lessaffected by the nature of the pore fluid whether it be fresh water orliquid hydrocarbon than said first signal; and d. means for comparingsaid first and second signals to obtain an indication of the presence ofoil versus fresh water in said formation.
 16. The system as recited inclaim 15, wherein said means for comparing includes means for combiningsaid first and second signals to generate a signal proportional to thedifferential therebetween, said differential signal signifying thepresence of oil versus fresh water in said formation.
 17. The apparatusas recited in claim 15, wherein said neutron source is adapted toirradiate said geological formation with neutrons having an averagesource energy selected such that the total effective neutron scatteringcross section of oil is larger that that of fresh water.
 18. A systemfor distinguishing oil from fresh water in a geological formationtraversed by a borehole, characterized by:a. a first neutron source forirradiating said geological formation with neutrons having a firstaverage source energy selected such that the difference between thetotal neutron cross section of oil and the total neutron cross sectionof fresh water has a first value; b. a first detector system fordetecting neutrons resulting from the irradiation of the formation bysaid neutrons having a first average source energy and for generating afirst signal indicative thereof; c. a second neutron source forirradiating said geological formation with neutrons having a secondaverage source energy different from said first average source energy,said second average source energy being selected such that thedifference between the total neutron cross section of oil and the totalneutron cross section of fresh water has a second value different fromsaid first value; d. a second detector system for detecting neutronsresulting from the irradiation of the formation and for generating asecond signal indicative thereof; and e. means for comparing said firstand second signals in order to obtain an indication of the presence ofoil of fresh water.
 19. The system as recited in claim 18 wherein eachof said detector systems includes means for detecting a spatial neutronflux distribution.
 20. The system as recited in claim 18 wherein one ofsaid detector systems for detecting neutrons includes means fordetecting a neutron flux amplitude at a single point.
 21. The system asrecited in claim 18 wherein said first and second average sourceenergies are selected such that the difference between the totaleffective neutron scattering cross sections of oil and fresh water isgreater for neutrons having said first average source energy than forneutrons having said second average source energy.
 22. The system asrecited in claim 18, wherein said first average source energy is suchthat the total neutron scattering cross-section mismatch between oil andfresh water is less than that for said second average source energy. 23.A system for distinguishing oil from fresh water in a geologicalformation traversed by a borehole, characterized by:a. a neutron sourcefor irradiating said geological formation with neutrons; b. a firstdetector system for detecting the neutron flux distribution resultingfrom the irradiation of said geological formation and for generating afirst signal indicative of formation porosity therefrom; c. a source forirradiating said geological formation with gamma rays; d. a seconddetector system for detecting the gamma ray flux resulting from thegamma ray irradiation of said geological formation and for generating asecond signal indicative of formation porosity therefrom; e. means forcomparing said first and second porosity signals derived from said firstand second detecting systems; and f. means responsive to the comparisonmeans of e. for generating and recording a signal whose value isindicative of the presence of oil or of fresh water in the geologicalformation.
 24. The system for distinguishing oil from fresh water asrecited in claim 23 wherein said first detector system includes adetector for detecting the epithermal neutron flux distribution.
 25. Theapparatus as recited in claim 23, wherein said neutron source is adaptedto irradiate said geological formation with neutrons having an averagesource energy selected such that the total effective neutron scatteringcross section of oil is larger than that of fresh water.
 26. A systemfor distinguishing oil from fresh water in a geological formationtraversed by a borehole, characterized by:a. a neutron source forirradiating said geological formation with neutrons; b. a detectorsystem for detecting the neutron flux resulting from the irradiation ofthe formation and for generating a first signal indicative of formationporosity therefrom; c. an acoustic energy generating system fortransmitting acoustic energy into said geological formation; d. anacoustic receiving system for detecting sound waves returning from theformation and for generating a second signal indicative of formationporosity therefrom; e. means for comparing said first and secondporosity signals; and f. means responsive to said comparison means forgenerating and recording a signal whose value is indicative of thepresence of oil or of fresh water in the geological formation.
 27. Theapparatus as recited in claim 26, wherein said neutron source is adaptedto irradiate said geological formation with neutrons having an averagesource energy selected such that the total effective neutron scatteringcross section of oil is larger than that of fresh water.
 28. A methodfor monitoring a geological formation to detect the displacement of afirst liquid having a first hydrogen density by a second liquid having asecond hydrogen density comprising the steps of:a. irradiating saidformation with neutrons and generating a first signal indicative of theresultant neutron flux prior to the displacement of said first liquid;b. irradiating said formation with neutrons and generating a secondsignal indicative of the resultant neutron flux subsequent to thedisplacement of said first liquid; c. converting each of said first andsecond signals into respective first and second signals indicative ofporosity; d. comparing said first and second porosity indicative signalsto derive a signal whose value is indicative of the displacement of saidfirst liquid by said second liquid; and e. in response to said comparingstep recording said signal whose value is indicative of the displacementof said first liquid by said second liquid.
 29. The method as recited inclaim 28 wherein said step of irradiating said formation with neutronsincludes irradiating said formation with a neutron flux whose averageneutron energy has been selected such that the total effective neutronscattering cross section of said first liquid is larger than that ofsaid second liquid.
 30. The method as recited in claim 29 wherein saidfirst liquid is oil and said second liquid is fresh water.